Natural gas is the most important fuel gas in the United States, and is also used extensively as a basic raw material in the petrochemical and other chemical process industries. The composition of natural gas varies widely from field to field. For example, a raw gas stream may contain as much as 95% methane, with small amounts of other hydrocarbons, nitrogen, carbon dioxide, hydrogen sulfide or water vapor. On the other hand, streams that contain relatively large proportions, up to say 10%, of propane, butane, or ethane, or combinations of these, are also commonly encountered, as are mixtures with a high carbon dioxide content. The heats of combustion of the principal hydrocarbon constituents are listed in the table below.
______________________________________ Component Btu value/cubic foot ______________________________________ Methane 1010 Ethane 1769 Propane 2517 Butane 3262 Pentane 4000 ______________________________________
For safety reasons, the Btu rating of natural gas that is to be carried through a pipeline is usually controlled within a fairly narrow range, typically 950-1050 Btu/cubic foot. Because of the higher Btu values of ethane, butane annd pentane, natural gases that contain significant proportions of these are too high in Btu value to be fed directly to a pipeline, or for direct use as commercial or domestic fuels. Equally importantly, ethane, propane and butane are of too much industrial value in their own right to be essentially wasted as secondary components in the gas mixture. Thus it can be seen that it is almost always necessary to subject raw natural gas to a treatment process of some kind, both to remove undesirable components such as sour gas, carbon dioxide or water vapor; to recover the valuable hydrocarbons, and to bring the Btu value to an industry standard level.
The conventional way to separate the hydrocarbon components is a refrigerated condensation process operating down to about -40.degree. C. More modern plants use a cryogenic isentropic expansion method, and operate down to -100.degree. C. The condensed liquids are separated from the gas stream, then subjected to fractional distillation under pressure to recover individual components. The gas residue frequently requires recompression before pipelining. These processes consume relatively large quantities of energy, which is reflected in the price of the finished gas.
It is also important to remove water vapor, which could otherwise condense in the pipeline with resulting corrosion. Dehydration is typically achieved by compression of the gas, followed by adsorption of the water vapor into water-drying agents such as glycol, activated alumina or bauxite, silica gel, and so on. Hydrogen sulfide and any other sulfur compounds present must also be reduced, not only because of toxicity, but also because they can cause corrosion in the pipeline, have an unpleasant odor, and give rise to air pollution when burnt. There are many commercial reagents that can be used for hydrogen sulfide removal; they involve the use of either a physical solvent or a chemical reagent in aqueous solution. Carbon dioxide, which can lower the heating value of the gas, is also removed this way. The most widely used solvent is monoethanolamine. Sometimes this is combined with diethylene glycol, so that the dehydration and desulfurization steps are carried out simultaneously. There is a disadvantage to these methods, in that some solvents used have a high affinity for the higher hydrocarbons, which may then be lost with the sour gas segment. The sulfur compounds removed from the gas are generally used to recover elemental sulfur by the Claus process.
From the above discussion, it is apparent that natural gas treatment involves a range of treatment steps that may be complex, costly, and may generate products that require further treatment. A simple, energy efficient process that can generate pipeline-quality methane in a single pass, and/or recover propane, butane and other useful hydrocarbons, would thus be of considerable benefit to the industry.
The use of membrane-based systems as an alternative to conventional technology to separate gases is known for some applications. For example, commercial systems for oxygen/nitrogen separation are now available under the name Generon.RTM. from Dow Chemical, Midland, Mich. Membrane systems that can recover hydrogen are offered by Permea, Inc., a subsidiary of Monsanto; and by DuPont under the name Permasep.RTM.. Grace Membrane Systems, a subsidiary of W. R. Grace, sells systems that can separate carbon dioxide from methane, or hydrogen from a variety of gas mixtures. Membranes have found some applications in the oil and gas industry, in hydrogen sulfide reduction, or in treating gas streams containing large volumes of carbon dioxide, typically arising from EOR (enhanced oil recovery). References that describe this type of application are for example U.S. Pat. Nos. 4,597,777; 4,589,896; 4,130,403; and 4,428,776. These references employ synthetic membranes made from glassy polymers, which have good selectivity for polar gases over the hydrocarbon components of the mixture. A typical membrane that has been used commercially, for example, is a cellulose triacetate hollow fiber, available from Dow/Cynara, or polysulfone, available from Monsanto. Glassy polymers, such as cellulose diacetate, cellulose triacetate or polysulfone, are, however, relatively unselective for one hydrocarbon over another, and are unsuitable for separating methane or ethane from C.sub.3 or C.sub.3 + hydrocarbons. In fact, these types of membrane often are more permeable to methane than to the C.sub.2 + hydrocarbons.
That rubbery membrane materials may be useful for performing some gas or vapor separations is known in the art, and is reflected in the patent literature. For example, U.S. Pat. No. 4,553,983 to Baker teaches a process for recovering organic vapors from air using rubbery membranes. Other references that mention the use of silicone rubber or other rubbery materials are for instance U.S. Pat. Nos. 4,230,463; 3,369,343; and 3,903,694.
The relatively high permeability of some rubbery polymers to hydrocarbon vapors has been reported in the literature. For example, a paper by G. E. Spangler, "Analysis of two membrane inlet systems on two potential trace vapor detectors", Amer. Lab., 7, (1975), 36, includes a graph of the permeability of silicone rubber to a large number of organic vapors. Similar data is available in an applications brochure for silicone rubber published by General Electric Company, and in a chapter by C. E. Rogers et al., "Separation by permeation through polymeric membranes", in Recent Developments in Separation Science, Vol. II, Chemical Rubber Co., Cleveland, OH, 1972. Silicone rubber membranes, however, although more permeable to ethane and the heavier hydrocarbons than to methane, are still relatively unselective. For example propane is only four times more permeable than methane. In general, this degree of selectivity is inadequate to treat natural gas, or similar, streams. It should be noted, also, that in all these references the permeability figures quoted are obtained from separate measurements on pure gas or vapor streams. As is known in the art, the ideal selectivity, expressed as a ratio of these permeabilities, is frequently not achieved with actual gas mixtures. This is because one or more constituents in the gas mixture may alter the membrane, for example by swelling, to such a degree that its properties are radically changed. Hence the behaviour of a membrane with samples of pure gases or vapors is not necessarily a reliable indicator of its behaviour in an actual separation system.
Thus, despite the theoretical knowledge described above, and the diverse teachings of the prior art as regards the use of membranes for gas separation, applicant believes there has not previously been a membrane-based process useful in separating methane from ethane and heavier hydrocarbon gases, and in recovery of propane and/or natural gas liquids (NGL) from natural or produced gas streams.